Oil sand extraction processes are used to liberate and separate bitumen from oil sand so the bitumen can be further processed. Numerous oil sand extraction processes have been developed and commercialized using water as a processing medium. One such water extraction process is the Clarke hot water extraction process, which recovers the bitumen product in the form of a bitumen froth stream.
The bitumen froth stream produced by the Clarke hot water process contains water in the range of 20 to 45%, more typically 30% by weight and minerals from 5 to 25%, more typically 10% by weight which must be reduced to levels acceptable for downstream processes.
At Clarke hot water process temperatures ranging from 40 to 80° C., bitumen in bitumen froth is both viscous and has a density similar to water. To permit separation by gravitational separation processes, commercial froth treatment processes involve the addition of a diluent to facilitate the separation of the diluted hydrocarbon phase from the water and minerals.
Initial commercial froth treatment processes utilized a hydrocarbon diluent in the boiling range of 170-400° C. commonly referred to as a naphtha diluent in a two stage centrifuging separation process. Limited unit capacity, capital and operational costs associated with centrifuges promoted applying alternate separation equipment for processing diluted bitumen froth such as those described in Canadian Patent No. 1,267,860 (Hann) and Canadian Patent No, 1,293,465 (Hyndman et al). In these processes, the diluent naphtha was blended with the bitumen froth at a weight ratio of diluent to bitumen (D/B) in the range of 0.3 to 1.0 and produced a diluted bitumen product with typically less than 4 weight percent water and 1 weight percent mineral which was suitable for dedicated bitumen upgrading processes. Generally, operating temperatures for these processes were specified such that diluted froth separation vessels were low pressure vessels with pressure ratings less than 105 kPag. Other froth separation processes using naphtha diluent such as those described in U.S. Pat. No. 3,901,791 (Baillie) and Canadian Patent No. 2,021,185 (Tipman et al) involve operating temperatures that require froth separation vessels rated for pressures up to 5000 kPag. Using conventional vessel sizing methods, the cost of pressure vessels and associated systems designed for and operated at this high pressure limits the commercial viability of these processes.
Heavy oils such as bitumen are sometimes described in terms of relative solubility as comprising: firstly, a pentane soluble fraction which, except for higher molecular weight and boiling point, resembles a distillate oil; secondly, a less soluble resin fraction; thirdly, a paraffinic insoluble asphaltene fraction characterized as high molecular weight organic compounds with sulphur, nitrogen, oxygen and metals that are often poisonous to catalysts used in heavy oil upgrading processes. It is well known in the art that paraffinic hydrocarbons precipitate asphaltenes from heavy oils to produce deasphalted heavy oil with contaminate levels acceptable for subsequent downstream upgrading processes. Descriptions of deasphalting operations may be found in U.S. Pat. No. 3,278,415 (Doderenz et al), U.S. Pat. No. 2,188,013 (Pilat et at) and U.S. Pat. No. 2,853,426 (Peet et al). In these processes contaminates follow the asphaltenes when the asphaltenes are precipitated by paraffinic solvents having compositions from C3 to C10 when the heavy oil is diluted with 2 to 10 times the volume of solvent.
High water and mineral content distinguish bitumen froth from the heavy oil deasphalted in the above processes. Some early attempts to adapt deasphalting operations to processing bitumen from oil sands are identified in U.S. Pat. No. 3,779,902 (Mitchell et al) and U.S. Pat. No. 4,634,520 (Angelov et al). These patents generally disclose precipitation of essentially a mineral free, deasphalted product, the ability to vary the amount of asphaltene precipitated, and the enhancement of asphaltene precipitation by addition of water and chemical agents.
Recent investigations in treating bitumen froth with paraffinic solvents as identified in Canadian Patents 2,149,737 (Tipman et al) and 2,217,300 (Tipman et al) have resulted in paraffinic froth treatment processes described in Canadian Patents 2,200,899 (Tipman et al); 2,232,929 (Birkholz et al); 2,350,907 (Picavet et al); 2,454,942 (Hyndman et al) and U.S. Pat. No. 6,007,709 (Duyvesteyn et al). Central to these processes are froth settling vessels (FSV) arranged in a counter-current flow configuration. In process configurations, counter-current flow refers to a processing scheme where a process medium is added to a stage in the process to extract a component in the feed to that stage, and the medium with the extracted component is blended into the feed of the preceding stage. Counter-current flow configurations are widely applied in process operations to achieve both product quality specifications and optimal recovery of a component with the number of stages dependent on the interaction between the desired component in the feed stream and the selected medium, and the efficiency of stage separations. In deasphalting operations processing heavy oil with low mineral solids, separation using counter-current flow can be achieved within a single separation vessel. However, rapidly setting mineral particles in bitumen froth preclude using a single separation vessel as this material tends to foul the internals of conventional deasphalting vessels.
FIG. 1 illustrates a two stage process such as disclosed in Canadian Patent No. 2,454,942 (Hyndman et al). In this process, bitumen froth 100 at 80-95° C. is mixed with overflow product 102 from a second stage FSV 104 at mixer 101 such that the solvent to bitumen ratio in the diluted froth stream 106 to a first stage FSV 108 is above the threshold to precipitate asphaltenes from the bitumen froth. For paraffinic froth treatment processes with pentane as the paraffinic solvent, the threshold solvent to bitumen ratio as known in the art is about 1.2 which significantly increases the feed volume to the FSV. The first stage FSV 108 separates the diluted froth into an overflow stream 110 comprising a partially to fully deasphalted oil with a low water and mineral content, and an underflow stream 112 containing the rejected asphaltenes, water, and minerals together with residual maltenes from the bitumen feed and solvent due to the stage efficiency. First stage underflow stream 112 is mixed with a paraffinic solvent 114 at mixer 115 to form a diluted feed 116 for the second stage FSV 104. The second stage FSV 104 recovers residual maltenes from the bitumen and solvent. It is important to recognize the different process functions of stages in a counter-current process configuration. In this case, the operation of first stage FSV 108 focuses on product quality and the second stage FSV 104 focuses on recovery of residual hydrocarbon from the underflow of the first stage FSV. Another aspect is that the process is operated at temperatures that require controlling the pressure in either stage such that solvent vaporization in the FSVs is limited. It is also understood by persons skilled in use of counter-current flow schemes that various aspects of the flow scheme can be modified to provide an optimized process configuration based on the characteristics of the feed or product. These aspects include the use of additional stages, the introduction of the feed stream at different stages within the overall flow scheme, and bypassing a portion of the media stream around a stage.
Independent of the stage in which the separation vessel is located, the introduced feed is separated into two outlet streams: an overflow and an underflow stream. By introducing feed between the two outlet streams, the vessel separation is also classed as counter-current by internal flow patterns. In contrast, vessels such as disclosed in Canadian patent 2,527,058 (Hann) are distinguished by vessel separations classed by internal flow patterns as co-current.
For all gravity based separation schemes, whether counter-current or co-current flow, the separation principles are governed by Stokes' Law whereby particles tend to separate in fluid media at a rate dependent on the viscous properties of the fluid and the mass density and size differential of the particles. In some applications, the solid phase is a liquid which forms immiscible droplets in the liquid phase.
For settlers that employ counter-current flow patterns, significant precedent literature exists to specify the vessel arrangement. In process industries, these vessels are frequently identified as clarifiers if the prime focus is on the overflow product and thickeners if the prime focus is on underflow product. In some cases, a single vessel due to specific fluid properties can encompass both objectives. In paraffinic froth treatment, the overflow stream accounts for a significant portion of the feed stream. The following discussion focuses on the adaptation of conventional clarifier procedures for specifying a first stage FSV producing a high quality deasphalted oil product from diluted bitumen feed. Similar adaptation of conventional thickener procedures apply to the specification of the last stage FSV.
Sizing of conventional clarifiers is derived from Stokes' Law for gravity settling of solids either as solid particles or immiscible liquid drops in a liquid phase. In some clarification applications, such as American Petroleum Institute (API) separators for treating water for environmental discharges, performance requirements based on Stokes' Law are reflected in regulations. However, many parameters that affect the settling behaviours cannot be adequately predicted in advance particularly, when coalescence, flocculation or other sedimentation enhancement processes are involved. Where coalescence, flocculation or other sedimentation enhancement processes occur naturally or artificially, settling tests are conducted that cover the expected operating envelope for the settling vessel. This includes the use of chemical additives, mixing or other techniques known to affect settler performance. Generally, the testing involves static jar settling tests to determine the bulk settling rate and involves mixing the feed and allowing the mixed feed stream to settle over time. Perry's Chemical Engineers Handbook 6th Edition outlines on pages 19-53 basic sedimentation test procedures available. Frequently the settling occurs in fluids that are relatively opaque and optical systems are employed in the testing.
Conversion of settling rates obtained from static test data by published design procedures tend to scale a clarifier for only 50% of the observed settling rate. Examples of such published procedures may be found in references such as Mineral Processing Plant Design, Practice And Control Proceedings: Andrew Mular, Doug Halbe, Derek Barratt SME 2002, or Perry's Chemical Engineers Handbook, 6th Edition, page 19-54. The scaling for 50% of the observed settling rate establishes the required settling area for the clarifier, and therefore the vessel diameter for cylindrical vessels such as settlers. The vessel diameter is proportionally related to the wall thickness required to contain the pressure of the vessel contents.
The settling test also provides static detention times to achieve the separation which represents the volume required in the clarifier above the interface to achieve the overflow quality. To account for turbulence and non-uniform flow, practitioners apply a detention factor when setting the height between the interface and the overflow such as disclosed in FIG. 19-71 of Perry's Chemical Engineering Handbook 6th Edition where detention factors range from 60% to 25%. For froth settling vessels, static detention times in conjunction with applied detention factors result in a diameter to depth ratio of 1:1. This volume is directly related to the weight of the vessel which affects the structural support and foundation requirements for the vessel. The larger the size of the vessel as influenced by design factors, the greater the vessel cost. Limiting the size of the vessel by reducing the height may be accomplished by making the cone angle on the vessel bottom relatively low (up to 10 degrees to horizontal). Rakes or similar scraping devices are used in such vessels to aid transport of solids on the low cone angle to a centre discharge.
The fact that current settler vessel design techniques apply design factors for both settling rates and detention times which tend to increase the size of the vessel and significantly increase the cost of the vessels is well known to the applicant.